Plural-depth buried seismic sensors acquisition system and method

ABSTRACT

A system for collecting seismic data includes plural seismic sensors. The seismic sensors are buried underground. In one application, a first set of seismic sensors are buried at a first depth and a second set of seismic sensors are buried at a second depth. In another application, the sensors alternate along a line, one sensor from the first set and a next sensor from a second set. In still another application, the sensors are randomly distributed below the ground.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is related to and claims the benefit of priorityof U.S. Provisional Application Ser. No. 61/707,278, filed Sep. 28,2012, and U.S. Provisional Application Ser. No. 61/707,284 having thetitle “Plural-Depth Buried Seismic Sensors Acquisition System andMethod,” and being authored by J. Cotton and E. Forgues, the entirecontents of which are incorporated herein by reference.

BACKGROUND

1. Technical Field

Embodiments of the subject matter disclosed herein generally relate tosystems and methods for using underground seismic sensors for collectingseismic data and, more particularly, to mechanisms and techniques forghost reduction in seismic acquisition.

2. Discussion of the Background

Land seismic data acquisition and processing may be used to generate aprofile (image) of the geophysical structure under the ground(subsurface). While this profile does not provide an accurate locationfor oil and gas reservoirs, it suggests, to those trained in the field,the presence or absence of such reservoirs. Thus, providing ahigh-resolution image of the subsurface is important, for example, tothose who need to determine where oil and gas reservoirs are located.

Traditionally, a land seismic survey is performed in the following way.Seismic sensors (e.g., geophones, hydrophones, accelerometers, etc. or acombination of them) are electrically connected to each other and thendeployed on the ground or below the ground. After all the seismicsensors have been deployed, one or more seismic sources are brought intothe field and actuated to generate the seismic waves. The seismic wavespropagate through the ground until they are reflected and/or refractedby various reflectors in the subsurface. The reflected and/or refractedwaves propagate to the seismic sensors, where they are recorded. Therecorded seismic waves may be used, among other things, for seismicmonitoring of producing oil fields.

Time-lapse (or 4D) seismic monitoring of producing oil fields is anaccepted method for optimization of field development and productrecovery, providing significant improvements in recovery rates andsavings in drilling costs. Time-lapse seismic reservoir monitoring isthe comparison of 3D seismic surveys at two or more points in time.Time-lapse seismic reservoir monitoring also has potential forincreasing the ability to image fluid movement between wells.

A traditional configuration for achieving a 4D seismic monitoring isillustrated in FIG. 1. FIG. 1 shows a system 10 for the acquisition ofseismic data. The system 10 includes receivers 12 positioned over anarea 12 a of a subsurface to be explored and buried at the same depthbelow the surface 14 of the Earth. A number of vibroseismic sources 16are also placed on the surface 14 in an area 16 a, in a vicinity of thearea 12 a of the receivers 12. A recording device 18 is connected to thereceivers 12 and placed, for example, in a station-truck 20. Each source16 may be composed of a variable number of vibrators, typically between1 and 5, and may include a local controller 22. Alternatively, thesource may be a shallow buried explosive charge or other known devicesfor generating a seismic source, e.g., a metal plate placed on theground and hammered with a hammer. A central controller 24 may bepresent to coordinate the shooting times of the sources 16. A GPS system26 may be used to time-correlate the sources 16 and the receivers 12.

With this configuration, sources 16 are controlled to generate seismicwaves, and the plurality of receivers 12 record waves reflected by theoil and/or gas reservoirs and other structures. The seismic survey maybe repeated at various time intervals, e.g., months or years apart, todetermine changes in the reservoirs. Although repeatability of sourceand receiver locations is generally easier to achieve onshore, thevariations caused by changes in near-surface can be significantly largerthan reservoir fluid displacement, making time-lapse 4D seismicacquisition and repeatability challenging. Thus, variations in seismicvelocity in the near-surface are a factor that impacts repeatability of4D surveys.

Several onshore time-lapse seismic case studies have shown the advantageof buried acquisition when looking at weak 4D signals (see Meunier etal, 2001, “Reservoir monitoring using permanent sources and verticalreceiver antennae: The Céré-la-Ronde case study,” The Leading Edge, 20,622-629, or Forgues et al, 2010, “Benefits of hydrophones for landseismic monitoring,” 72^(nd) Conference and Exhibition, EAGE, ExtendedAbstracts, B034, the content of both of which are incorporated herein byreference). Although the seismic repeatability is improved when sourcesand sensors are buried, a part of the wave field (the up-going part) isstill transmitted through the weathering layer and reflected at thesurface. These surface reflected waves, often called “ghosts,” areaffected by the near surface variations and can vary in time. In thecase of daily seismic monitoring, small reservoir variations that aredesired to be measured can be spoiled by the near surface waves thatfluctuate in time due to temperature and moisture variation, because thewaves coming from the reservoir interfere with the near-surface waves.In marine acquisition, several strategies have been developed fordeghosting data using the streamer configuration.

However, the presence of the ghosts in the recorded seismic data remainsa problem for the existing acquisition methods. Further, there is a needto improve the 4D seismic repeatability, increase the frequency contentof the seismic data and reduce the number of sensors. Thus, there is aneed for a system and method that address the above noted deficienciesof the current art.

SUMMARY OF THE INVENTION

According to an embodiment, there is a seismic data acquisition systemfor recording seismic waves related to a subsurface to be surveyed. Thesystem includes plural seismic sensors located at corresponding depthsunderground, wherein the depths are randomly distributed between aminimum depth d_(min) and a maximum depth d_(max). The plural seismicsensors are buried underground beneath a weathering layer, and they aremonitoring the subsurface for determining changes in the subsurface.

According to an embodiment, there is a method for recording seismicwaves related to a subsurface to be surveyed. The method includesburying plural seismic sensors at corresponding depths underground,wherein the depths are randomly distributed between a minimum depthd_(min) and a maximum depth d_(max), wherein the plural seismic sensorsare buried underground beneath a weathering layer; recording with theplural seismic sensors seismic waves generated by seismic sources; andprocessing the recorded seismic waves to remove a ghost and to generatea final image of the subsurface.

According to another embodiment, there is a seismic data acquisitionsystem for recording seismic waves related to a subsurface to besurveyed. The system includes first and second sets of seismic sensorsdistributed underground at first and second depths (d1, d2). Each sensorof the first set of seismic sensors is located at the first depth (d1),and each sensor of the second set of seismic sensors is located at thesecond depth (d2). The first and second sets of seismic sensors areburied underground beneath a weathering layer, and the first and secondsets of seismic sensors are monitoring the subsurface for determiningchanges in the subsurface.

According to yet another embodiment, there is a method for recordingseismic waves related to a subsurface to be surveyed. The methodincludes burying first and second sets of seismic sensors at first andsecond depths underground, wherein each sensor of the first set ofseismic sensors is located at the first depth (d1), and each sensor ofthe second set of seismic sensors is located at the second depth (d2),recording with the first and second sets of seismic sensors seismicwaves generated by seismic sources; and processing the recorded seismicwaves to remove a ghost and to generate a final image of the subsurface.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, reference isnow made to the following descriptions taken in conjunction with theaccompanying drawings, in which:

FIG. 1 is a schematic diagram of a conventional land seismic acquisitionsystem;

FIG. 2 is a schematic diagram of a dual-depth sensor system according toan exemplary embodiment;

FIGS. 3A and 3B illustrate shot points recorded daily for the dual-depthsensor system;

FIG. 4 is a schematic diagram of a near-surface S-P converted wave;

FIG. 5 illustrate SP-waves attenuation using a radon transform accordingto an exemplary embodiment;

FIG. 6 illustrate deghosting results with PZ summation and dual-depthsensor system according to an exemplary embodiment;

FIG. 7 illustrate SP-waves attenuation using a single hydrophone lineand a dual-depth hydrophone system according to an exemplary embodiment;

FIGS. 8A-F illustrate SP converted wave attenuation and dual sensordeghosting according to an exemplary embodiment;

FIG. 9 is a side view of an alternating dual-depth sensor systemaccording to an exemplary embodiment;

FIG. 10 is an aerial view of an alternating dual-depth sensor systemaccording to an exemplary embodiment;

FIG. 11 is a side view of a random depth sensor system according to anexemplary embodiment;

FIGS. 12A to 12E illustrate a traditional single depth sensor system andassociated amplitude spectra;

FIGS. 13A to 13E illustrate an alternate dual-depth sensor system andassociated amplitude spectra according to an exemplary embodiment;

FIGS. 14A to 14E illustrate a random depth sensor system and associatedamplitude spectra according to an exemplary embodiment;

FIG. 15 illustrate travel time variations and pressure measured at afirst location for various sensor systems according to exemplaryembodiments;

FIG. 16 illustrate travel time variations and pressure measured at asecond location for various sensor systems according to exemplaryembodiments;

FIG. 17 is a flowchart of a method for processing data acquired withplural-depth sensor systems according to an exemplary embodiment;

FIG. 18 is a 2D stack section according to an exemplary embodiment;

FIG. 19 illustrates a steam injection rate, seismic travel time shiftsand amplitudes according to exemplary embodiments;

FIGS. 20A and 20B illustrate pressure, time shift and amplitude computedon the stack section according to exemplary embodiments;

FIG. 21 is a flow chart of a method for recording seismic data with amulti-depth sensor system according to an exemplary embodiment;

FIG. 22 is a flow chart of a method for recording seismic data with arandom-depth sensor system according to an exemplary embodiment;

FIG. 23 is a schematic diagram of a computing device capable ofimplementing one or more of the methods discussed in the exemplaryembodiments.

DETAILED DESCRIPTION OF THE INVENTION

The following description of the exemplary embodiments refers to theaccompanying drawings. The same reference numbers in different drawingsidentify the same or similar elements. The following detaileddescription does not limit the invention. Instead, the scope of theinvention is defined by the appended claims. The following embodimentsare discussed, for simplicity, with regard to the terminology andstructure of a land seismic system that includes hydrophones. However,the embodiments to be discussed next are not limited to hydrophones orto a land seismic system. The novel features of the embodiments may beapplied to any seismic sensor, combination of seismic sensors and alsoin a marine context.

Reference throughout the specification to “one embodiment” or “anembodiment” means that a particular feature, structure or characteristicdescribed in connection with an embodiment is included in at least oneembodiment of the subject matter disclosed. Thus, the appearance of thephrases “in one embodiment” or “in an embodiment” in various placesthroughout the specification is not necessarily referring to the sameembodiment. Further, the particular features, structures orcharacteristics may be combined in any suitable manner in one or moreembodiments.

According to an exemplary embodiment, there is a system that includesplural seismic sensors. The sensors may include, among others, at leastone of a geophone, a hydrophone, an accelerometer, etc. or a combinationof them. The system may be deployed onshore or offshore. If deployedoffshore, the seismic sensors may be buried under the sea floor.However, by placing the seismic sensors bellow a free surface, a ghostreflection is introduced by the free surface. The ghost reflectioninterferes with the primary waves and thus, the data quality and itsrepeatability is degraded, especially in the 4D context. Thus, insteadof trying to place all the sensors at a same depth (flat mat of sensors)as traditionally performed, the novel system uses plural-depth sensors,alternating multi-depth sensors and/or random-depth sensors in order tofacilitate the primary and ghost separation. By using these novelconcepts, the 4D data repeatability is improved compared to theconventional buried flat spread. According to another exemplaryembodiment, a dual-depth sensor acquisition system may be used. Stillaccording to another exemplary embodiment, an alternating multiple-depthsensor acquisition system may be used. This last system generates thesame results as the multiple-depth sensor system but uses half thenumber of receivers. These embodiments are now discussed in more detail.

According to an exemplary embodiment illustrated in FIG. 2, aplural-depth (dual-depth in this particular embodiment) sensor system200 may include plural seismic sources 202 and sets of seismic sensors204 i and 206 i distributed in two planes 205 and 207, respectively. Inone application, the set of seismic sensors 204 i are arranged to mirrorthe set of seismic sensors 206 i relative to a plane P having a depth of(d1+d2)/2. In another application, the number of sensors 204 i isdifferent than the number of sensors 206 i. Both the sources and theseismic sensors are buried below the Earth's surface 210.

In one application, the sources and the sensors are buried below theweathering layer 212 to preserve primary reflected waves 214 b frombeing affected by climatic changes. FIG. 2 shows that a source 202 emitsa seismic wave 214 a, that gets reflected in the subsurface 216, thatincludes the reservoir 281. The reflected wave 214 b is then recorded bya sensor 206 p. At the same time, another reflected wave 214 c arrivesat the surface 210 and gets again reflected, forming the ghost wave 214d that is also recorded by the sensor 206 p.

In one application, the first set of sensors 204 i is located at a depthd1, which may be substantially 9 m, while the second set of sensors 206i is located at a depth d2, which may be substantially 6 m from thesurface 210. Other values for the depths d1 and d2 may be used. Theseismic sources 202 may be buried at a depth D substantially equal to 25m, i.e., below the seismic sensors. The seismic source 202 may emitcontinuously during the monitoring period, e.g., more than a year.Geophones 230 i have been buried next to the first set of seismicsensors (e.g., hydrophones) 204 i for testing the P-Z summation.However, they are not necessary for the purpose of this invention.

The data recorded with the first set of seismic sensors (hydrophones) isshow in FIG. 3A while the data recorded with the geophones, at the samedepth of 9 m, is shown in FIG. 3B. It is noted that the geophones areabout 15 dB noisier than the hydrophones.

At a depth of 9 m, where both hydrophones and geophones are located, theVp/Vs ratio (i.e., the ratio of the speed of a P-wave and the speed of aS-wave) has been measured close to 7. This suggests that there will be asignificantly higher ratio of shear to compressional waves on geophonescompared to hydrophones. This theory is supported by the dataobservation where the quantity of S-wave and the noise level (mostlyRayleigh waves due to anthropic activities) is lower for hydrophonesthan for geophones.

On hydrophones, reflections at the reservoir (˜600 ms) interfere withrather energetic and low apparent velocity waves interpreted as S-Pwaves 240 (see FIG. 2) converted at the near surface (see Hornman et al,2012 “Continuous monitoring of thermal EOR at Schoonebeek forintelligent reservoir management,” Proceedings of the InternationalIntelligent Energy Conference, SPE, 150215, the entire content of whichis incorporated herein by reference). The strong S-wave contentgenerated by the buried source travels up to the surface and isconverted into P-waves when it reaches near-surface heterogeneities.These waves 240 are then back-scattered or refracted to the sensors withan almost horizontal incidence which is not recorded by the geophonesbut only by the hydrophones.

A more precise study has shown that the main part of these convertedwaves came from an unconsolidated filled ditch as illustrated in FIG. 4.Like the surface ghost, these near-surface converted waves fluctuatewith respect to seasonal changes (soil moisture, frost and groundtemperature) and can be considered as 4D noise for reservoir monitoring.

In this regard, it has been observed that variations of the SP-waves arefinely correlated with the surface temperature with values of 0.2 ms/°C. and 1.7%/° C. for time shift and amplitude respectively. In order toreduce their impact, it is possible to use the processing concept ofwave attenuation in the time-lapse domain in a similar manner to the oneused by Bianchi et al., 2004, “Acquisition and processing challenges incontinuous active reservoir monitoring,” 74^(th) Annual InternationalMeeting, SEG, Expanded Abstracts, 2263-2266, the entire content of whichis incorporated herein by reference. Then, the residual waves arereduced using a high resolution radon transform in the Tau-P domain asillustrated in FIG. 5.

Several ways to reduce the ghost effect can be envisaged in permanentburied acquisition. Firstly, it is possible to use the natural waveattenuation of the unconsolidated near surface and increase the sourceand receiver depths. Secondly, it is possible to use dual sensors at thesame location (geophone and hydrophone) and sum them after data unitconversion (i.e., the P-Z summation). Finally, the use of dual-depthhydrophones becomes significantly more attractive. For this lastapproach, it is possible to use the parametric wave-field decompositionproposed by Leaney (1990, “Parametric wavefield decomposition andapplications,” 60^(th) Annual International Meeting, SEG, ExpandedAbstracts, 1097-1100, the entire content of which is incorporated hereinby reference) to separate the up-going and down-going waves fromhydrophones at 6 m and 9 m with a minimization of the calendar variationas a criterion as illustrated in FIG. 6. FIG. 6 shows deghosting resultsobtained with a PZ summation (i.e., using both hydrophone and geophonedata) and with the dual-depth sensor system of FIG. 2.

As most of the converted waves have been removed, it is possible toconsider that the remaining 4D noise is mainly due to the receiver ghostvariations. It may be assumed that the propagation is vertical and thatthe two hydrophones have an identical response. Thus, the 4D noise abovethe reservoir is reduced, and the 4D signal at the reservoir is visiblewhen the injection starts as illustrated in FIG. 7. To evaluate theimprovement provided by the different processing steps, therepeatability is analyzed in a 40 ms time window just above thereservoir. Predictability is sensitive to the length of the correlationwindow and to the number of lags in the correlations, so absolutenumbers are not meaningful (see Kragh and Christie, 2002, “Seismicrepeatability, normalized rms, and predictability,” The Leading Edge,21, 640-647). Nevertheless, predictability gives a relative idea of theseismic repeatability improvement with the different processing steps.

It can be seen in FIGS. 8A-F that the S-P converted wave attenuation andthe dual sensor deghosting lead to a significant enhancement in theseismic repeatability as both NRMS and predictability are improved.

According to another exemplary embodiment illustrated in FIG. 9, insteadof placing the first and second sets of seismic sensors in pairs at thedifferent depths d1 and d2, they may distributed in an alternatingdual-depth arrangement as shown in FIG. 9. In other words, a sensor 904i from the first set of sensors is not placed on a same vertical line asa sensor 906 i from the second set of sensors. In one application, adistance l1 between two adjacent sensors 904 i and 904 j has a fixedvalue and a distance l2 between two adjacent sensors 906 i and 906 j hasanother fixed value. In one application, l1=l2. In another application,each of the distances l1 and l2 may vary along the line of sensors.

It is noted that an aerial representation of the system 900 is shown inFIG. 10 and indicates that the first set of sensors 904 _(i) and thesecond set of sensors 906 _(i) may be buried together with other sets ofsensors 914 _(i) and 916 _(i) that may have similar configurations withthe set of sensors 904 _(i) and 906 _(i). In other words, the sensorsthat are buried below the surface 210 may form plural lines 920 _(i). Aline may include a first set of seismic sensors 904 _(i) and a secondset of seismic sensors 906 _(i), and the seismic sensors from the twosets alternate along the line.

It is further noted that although the above embodiments have beendiscussed with reference to a land seismic acquisition system, the sameis true for a marine seismic acquisition system with the difference thatthe land surface 201 becomes the sea bed and the sensors are buried inthe seabed. Also, the embodiments discussed herein are applicable notonly when a source 202 generates seismic waves but also when the earthitself generates the seismic surfaces, e.g., a fracture in the reservoir218 may be the seismic source. Other events that may constitute aseismic source are changes in the reservoir produced by steam injection,pressure injection, etc.

According to another exemplary embodiment illustrated in FIG. 11, asystem 1100 has the seismic sensors 1100 i randomly distributed in termsof their depth. FIG. 11 shows only a line of sensors randomlydistributed in depth, i.e., a depth of any sensor is randomlydistributed between a minimum depth d_(min) and a maximum depth d_(max).The values of d_(min) and d_(max) may vary from survey to survey. In oneapplication, the value d_(max) is smaller than a depth of the seismicsources 202. The system 1100 may include more than a line of suchsensors. In one application, each line is different from another line ofthe system.

FIGS. 12A to 14E illustrate a comparison between the traditional singledepth sensor system having seismic sensors distributed at a same depth(FIG. 12A), the novel system having alternating dual-depth sensors (FIG.13A) and the random-depth sensor system (FIG. 14A). FIGS. 12B, 13B and14B show the individual traces in the common middle point gather, FIGS.12C, 13C and 14C show the phases of the up-going waves, FIGS. 12D, 13D,and 14D show the CMP trace, and FIGS. 12E, 13E, and 14E illustrate theamplitude spectra of the CMP. It is noted how strong the notches 1200and 1202 (FIG. 12E) are for the conventional system and how reduced theyare in FIGS. 13E and 14E for the novel systems.

Other advantages of the novel systems are illustrated in FIGS. 15 and16. FIG. 15 plots the travel-time variations (in ms) versus time for adual hydrophone (DH) system, an alternating hydrophone system (AH) and atraditional single hydrophone (SH) system. FIG. 16 plots the same butfor another observation well. Both figures indicate that the novelsystems detect not only very small time shifts but also the smallamplitude variations due to steam injection in the reservoir. Further,it is noted that the novel embodiments of alternating sensors and therandomly distributed sensors use less sensors than a dual-depth sensorsystem.

A couple of considerations regarding data processing are now discussed.These considerations are discussed with regard to the dual-depth seismicsystem illustrated in FIG. 2. However, these considerations are equallyapplicable to the other systems illustrated in FIGS. 9 and 11.

It is desired that the data processing preserves the amplitudes of thewaves. Position errors associated with the location of the sensors for4D seismic acquisitions is minimized because the sensors and sources areburied. Further, a good coupling between the earth and the sensorsand/or sources is achieved by burring the sensors. Furthermore, nearsurface effects are attenuated in processing. However, source and sensorghosts are transmitted through the weathering layer and may affect therepeatability of the signal. S-P wave interference needs to beconsidered.

The data processing flow, illustrated in FIG. 17, includes a step 1700of muting the S-wave cone (i.e., removing the cone shown in FIGS. 3A and3B), a step 1702 of attenuation of calendar variations of near surfaceS-P wave conversion, and a step 1704 of ghost-removal using, forexample, dual-depth hydrophone summation at 6 and 9 m (depending on thetype of survey). Further, in step 1706, the daily stack section iscomputed with the same velocity model, and in step 1708 the 4D attributecomputation is performed by cross-correlation with a reference.

FIG. 18 shows the low-fold (<12), stack section. Element 1800 representsthe horizontal injector wells, elements 1802 and 1804 representobservation wells, and elements 1806 and 1808 represent producing wells.Area 1810 is further enlarged in the following figures. Although theseismic response is rather poor on the left side of the profile, strongreflectors around the reservoir can be mapped. From one day to the next,it is virtually impossible to see changes in the stack section while 4Dreservoir variations can be measured. The current daily stack section iscross-correlated on a trace by trace basis with a reference stackobtained before injection. Time shifts and amplitude variations are thenpicked on these cross-correlations to obtain 4D attributes. The lengthsof the correlation windows may be 100 and 20 ms for the travel-time andamplitude, respectively.

FIG. 19 shows both the seismic time shifts 1900 measured above and belowthe reservoir, the amplitude 1902, and the steam injection rate 1904 atthe injector location. The steam injection started on May 9 and the fullinjection rate was reached around May 24. Also some temporary break downin the injection occurred due to maintenance on pumps. Curve 1906represents the steam injection rate 1904 correlated with the seismictravel time shift 1900.

While there is virtually no change above the reservoir on the seismicreflection times, starts and stops of the injection are detected almostinstantaneously on the time shift curves and with some delay on theamplitude curves. This increase in time shift (actually corresponding toa slowdown) can be interpreted as a pressure effect as it occurs rapidlyover a large area.

The maximum observed cumulative variation of amplitude and time shift is10% and 0.4 ms, respectively, after three months of steam injectionnearby the injector. During the same period, the daily time shift isabout 6 μs and daily amplitude variation is about 0.1%.

FIGS. 20A and 20B compare time shift 2000 and amplitude 2002 curves withthe reservoir pressure curve 2004 measured at the two observation wells1802 and 1804. The measured time shift encompasses a combined effect ofpressure, temperature, gas saturation and steam. Ideally, thesecontributions can be discriminated using amplitude variations.

The swift spatial extension time shift values over a large area are dueto pressure changes. Pressure variations with variable amplitude areobserved suggesting that some areas are less connected to the injectorthan other areas. It is noted that these variations do not reach theproduction wells after almost 3 months after the injection. Thiscorroborates with the well gauges measurements showing that thetemperature at two production wells is still low. No temperature changeis measured at the observation wells indicating that the changes arepressure-induced only, which is consistent with the high correlationbetween time-shifts and pressure with about 8 μs per bar in FIGS. 20Aand 20B.

Regarding the amplitudes, it is observed a drastic change one monthafter the injection start up at the observation well 1802 located at adistance of 160 m from the injection point. The same one-month delayedresponse is observed after a temporary stop of the injection. It isexpected a theoretical propagation of 5 m a day if it was to beexplained by a physical phenomenon. Yet, there is almost no observedvariation at the western observation well 1804, which is only 80 m away.It is suspected an unknown cause that prevents the propagation of theobserved values. This should be calibrated by a reservoir model toconfirm that the observed behavior is induced by both the steam and thepresence of faults.

The precision and stability of the measurements allowed detection notonly of a small time shift but also of a small variation in amplitude.The measurements complement those made in observations wells and shouldenable the reservoir engineers to construct more accurate dynamic modelsfor better reservoir management decisions. As measured on observationand production wells, the steam field did not follow the expected pathas described by modeling but seems to be either stopped by a fault or tofollow yet another, more complex path that would be detected by a 3Dacquisition design.

The above-described systems may be used in the field to monitor areservoir. Thus, a method for monitoring a reservoir is now discussedwith regard to FIG. 21. The method includes a step 2100 of buryingplural seismic sensors (1100 _(i)) at corresponding depths underground,wherein the depths are randomly distributed between a minimum depthd_(min) and a maximum depth d_(max), wherein the plural seismic sensors(1100 _(i)) are buried underground beneath a weathering layer (212); astep 2102 of recording with the plural seismic sensors (1100 _(i))seismic waves generated by seismic sources; and a step 2104 ofprocessing the recorded seismic waves to remove a ghost and to generatea final image of the subsurface.

Another method for monitoring a reservoir is discussed with regard toFIG. 22. The method includes a step 2200 of burying first and secondsets of seismic sensors (204 _(i), 206 _(i)) at first and second depthsunderground, wherein each sensor of the first set of seismic sensors(204 _(i)) is located at the first depth (d1), and each sensor of thesecond set of seismic sensors (206 _(i)) is located at the second depth(d2), a step 2202 of recording with the first and second sets of seismicsensors (204 _(i), 206 _(i)) seismic waves generated by seismic sources;and a step 2204 of processing the recorded seismic waves to remove aghost and to generate a final image of the subsurface.

The above methods and others may be implemented in a computing systemspecifically configured to drive the seismic sources and to receive theseismic data recorded by the seismic sensors. An example of arepresentative computing system capable of carrying out operations inaccordance with the exemplary embodiments is illustrated in FIG. 22.Hardware, firmware, software or a combination thereof may be used toperform the various steps and operations described herein.

The exemplary computing system 2300 suitable for performing theactivities described in the exemplary embodiments may include server2301. Such a server 2301 may include a central processor (CPU) 2302coupled to a random access memory (RAM) 2304 and to a read-only memory(ROM) 2306. The ROM 2306 may also be other types of storage media tostore programs, such as programmable ROM (PROM), erasable PROM (EPROM),etc. The processor 2302 may communicate with other internal and externalcomponents through input/output (I/O) circuitry 2308 and bussing 2310,to provide control signals and the like. The processor 2302 carries outa variety of functions as are known in the art, as dictated by softwareand/or firmware instructions.

The server 2301 may also include one or more data storage devices,including a hard drive 2312, CD-ROM drives 2314, and other hardwarecapable of reading and/or storing information such as DVD, etc. In oneembodiment, software for carrying out the above-discussed steps may bestored and distributed on a CD-ROM 2316, removable memory device 2318 orother form of media capable of portably storing information. Thesestorage media may be inserted into, and read by, devices such as theCD-ROM drive 2314, the disk drive 2312, etc. The server 2301 may becoupled to a display 2320, which may be any type of known display orpresentation screen, such as LCD, LED displays, plasma display, cathoderay tubes (CRT), etc. A user input interface 2322 is provided, includingone or more user interface mechanisms such as a mouse, keyboard,microphone, touch pad, touch screen, voice-recognition system, etc.

The server 2301 may be coupled to other computing devices, such as thelandline and/or wireless terminals via a network. The server may be partof a larger network configuration as in a global area network (GAN) suchas the Internet 2328, which allows ultimate connection to the variouslandline and/or mobile client devices. The computing device may beimplemented on a vehicle that performs a land seismic survey.

The disclosed exemplary embodiments provide a system and a method formechanically deploying geophones. It should be understood that thisdescription is not intended to limit the invention. On the contrary, theexemplary embodiments are intended to cover alternatives, modificationsand equivalents, which are included in the spirit and scope of theinvention as defined by the appended claims. Further, in the detaileddescription of the exemplary embodiments, numerous specific details areset forth in order to provide a comprehensive understanding of theclaimed invention. However, one skilled in the art would understand thatvarious embodiments may be practiced without such specific details.

Although the features and elements of the present exemplary embodimentsare described in the embodiments in particular combinations, eachfeature or element can be used alone without the other features andelements of the embodiments or in various combinations with or withoutother features and elements disclosed herein.

This written description uses examples of the subject matter disclosedto enable any person skilled in the art to practice the same, includingmaking and using any devices or systems and performing any incorporatedmethods. The patentable scope of the subject matter is defined by theclaims, and may include other examples that occur to those skilled inthe art. Such other examples are intended to be within the scope of theclaims.

1-8. (canceled)
 9. A seismic data acquisition system for recordingseismic waves related to a subsurface to be surveyed, the systemcomprising: first and second sets of seismic sensors distributedunderground at first and second depths (d1, d2), wherein each sensor ofthe first set of seismic sensors is located at the first depth (d1), andeach sensor of the second set of seismic sensors is located at thesecond depth (d2), the first and second sets of seismic sensors areburied underground beneath a weathering layer, and the first and secondsets of seismic sensors are monitoring the subsurface for determiningchanges in the subsurface.
 10. The system of claim 9, wherein a sensorfrom the first set of seismic sensors is paired with a sensor from thesecond set of seismic sensors to be located on a same vertical linerelative to a surface of the Earth.
 11. The system of claim 9, whereinthe first set of seismic sensors mirrors the second set of seismicsensors.
 12. The system of claim 9, wherein projections of the first andsecond sets of seismic sensors on the surface form a line with alternatesensors belonging to each set.
 13. The system of claim 9, wherein thefirst and second sets of seismic sensors form a line of sensors whenviewed from above ground.
 14. The system of claim 13, furthercomprising: third and fourth sets of sensors that form a second line,the third set being distributed at the first depth and the fourth setbeing distributed at the second depth.
 15. The system of claim 9,wherein the first and second sets of seismic sensors include at leastone of a hydrophone, geophone, accelerometer or a combination thereof.16. The system of claim 9, wherein the subsurface is below the oceanbottom.
 17. The system of claim 9, further comprising: plural seismicsources buried underground, wherein the plural seismic sources arelocated at a same depth.
 18. The system of claim 17, wherein the depthof the plural seismic sources is deeper than the first and seconddepths.
 19. A method for recording seismic waves related to a subsurfaceto be surveyed, the method comprising: burying first and second sets ofseismic sensors at first and second depths underground, wherein eachsensor of the first set of seismic sensors is located at the first depth(d1), and each sensor of the second set of seismic sensors is located atthe second depth (d2); recording with the first and second sets ofseismic sensors seismic waves generated by seismic sources; andprocessing the recorded seismic waves to remove a ghost and to generatea final image of the subsurface.
 20. The method of claim 19, wherein thefirst and second sets of seismic sensors are buried underground beneatha weathering layer.
 21. The method of claim 19, wherein a sensor fromthe first set of seismic sensors is paired with a sensor from the secondset of seismic sensors to be located on a same vertical line relative toa surface of the Earth.
 22. The method of claim 19, wherein the firstset of seismic sensors mirrors the second set of seismic sensors. 23.The method of claim 19, wherein projections of the first and second setsof seismic sensors on the surface form a line with alternate sensorsbelonging to each set.
 24. The method of claim 19, wherein the first andsecond sets of seismic sensors form a line of sensors when viewed fromabove ground.
 25. The method of claim 24, further comprising: buryingthird and fourth sets of sensors underground to form a second line, thethird set being distributed at the first depth and the fourth set beingdistributed at the second depth.
 26. The method of claim 19, wherein thefirst and second sets of seismic sensors include at least one of ahydrophone, geophone, accelerometer or a combination thereof.
 27. Themethod of claim 19, wherein the subsurface is below an ocean bottom. 28.The method of claim 19, further comprising: burying plural seismicsources underground, wherein the plural seismic sources are located at asame source depth, which is deeper than the first and second depths.